When an oil or gas well produces water (generally with a large content of dissolved salts), there is a possibility for scaling to form. This may also occur in deposits where water injection is used as an improved recovery system, or when using gas with high CO2 content and other contaminants. The most common scaling formed is barium sulfate or calcium carbonate.
Buildup of mineral sediments or incrustations may form in pipes both on the surface and in the bottom of the well, or even inside the porous medium in the formation of the oil deposit itself, which causes serious backup problems or even full blockages in pipes.
The techniques within the oil industry for eliminating scaling must be quick, not harmful with the formation and to the environment. Techniques using chemicals are the most common because they are the most economical. When scaling is formed by carbonates, hydrochloric acid (HCI) is the most widely used to dissolve and remove scaling, but this acid loses its effectiveness with the precipitated calcium sulfate or other incrustations, in addition to having special care for its use. Although there are methods used where a solvent is utilized together with washers containing normal or viscoelastic surfactants, these are very selective products, making it necessary for versatile formulations for different scaling types.
HCI, as mentioned before, is the most widely used chemical compound for eliminating this type of scaling due to its cost, but it is also the acid with the fastest reaction, and therefore, a fast depletion of its effect. As a result, this is the reason why formulations which react gradually are recommended as they have a greater reach within a formation.
The application of scaling treatment is varied according to the location, and goes from solely pumping the dissolving product in a duct or well to a mixture with organic and inorganic solvents and surfactant agents, by using flexible piping, capillary piping or in the same gas injection for pneumatic pumping. The most appropriate application is the most convenient in accordance with the problem at hand.
The chemical inhibition process involves the preferential absorption of the inhibitor molecules in these buildup locations. Consequently, the crystal will stop developing when the inhibitor molecules have occupied all these active zones Inhibitors act by controlling the scale deposits when they chemically interact with the crystal nucleation locations and substantially reduce their development rates by altering their surfaces. These are known as initiation inhibitors. They also act by sequestering the ions that precipitate and form scaling.
A scale inhibitor must satisfy several conditions in order to have a prolonged use. The following are among these conditions:                Be compatible (not to form reaction products with other system chemicals which causes its inactivation).        Be thermally stable (especially to the conditions in the bottom of the well) and hydrolytically stable for long terms.        Bacteriologically not sensitive.        Modify the size of crystals (form a tendency to disperse).        Delay or block the scaling precipitation process to a low concentration.        Must not promote emulsions.        Must be able to be monitored in the return fluids.        
On the other hand, the inhibitor's maximum efficiency is threatened by:                Salinity and pH of the water that comes in contact with the inhibitor.        The water chemical composition, magnesium content and dissolved iron must be low.        Presence and type of suspended solids (the inhibitor is not yet “smart” and acts upon everything soluble traveling in the medium).        System temperature.        
In order to obtain a successful inhibition, there must be a sufficient concentration of inhibitor molecules accompanying the fluid extracted from the well. This condition may be assured only if the inhibitor is held in the formation and gradually desorbed along with the produced fluid.